Natural fluids such as crude oil and natural gas residing in subterranean porous formations are produced by drilling wells into the formation. Ambient pressure in the formation generally drives the fluid into and up the well. Surface pumps are used to enhance flow.
It is common practice to stimulate recovery of fluids from subterranean porous formations by fracturing the porous formation to open new pathways for flow to the well. One commonly used technique for fracturing formations is hydrofracturing. To hydrofracture a formation, a fracture fluid is injected by a pump located on the surface above the well into the formation through a well-bore. The fracture fluid is pumped at a rate sufficient to build up pressure in the well. The pressure is transmitted to the fluid in the porous formation and induces fractures in the formation.
Pressurized fracture fluid flows into the formation through perforations in the steel pipe which lines the well. The perforations are formed in pipe sections adjacent to sectors of the formation to be fractured by explosive charges or by high pressure jets. The fractures initiate at the well-bore and propagate radially outward into the formation. Commonly, solid particles, called propping agents, are dispersed in the fracture fluid. The propping agent deposits into the fracture fissures and holds them open. Propping agents have sufficient compressive strength to withstand the pressure in the formation, but are not abrasive against the formation. Common propping agents include sand, sintered bauxite, and polymer resin coated proppants.
Fracture fluids are generally aqueous; because water is effective, accessible, and cheap. Commonly, thickeners, hydratable polymeric water gelling materials, are added to the water to increase the viscosity of the fracture fluid. Viscosification is required to reduce leakage from the fracture fissures during fracturing and to promote suspension of propping agents. Fracture fluids are subjected to high shear stresses as they are pumped through the well and into the formation. The intermolecular bonds of the thickening agent molecules in solution must be sufficiently strong to resist shear cleavage during the hydrofracturing process. Commercially used thickening agents include synthetic products, e.g., polyethylene oxides, polyacrylates, polyacrylamides and polyetherglycols, and natural polymers like starch, guar, cellullose derivatives, lignites, carrageenan, and locust bean gum. Cost and performance effectiveness of natural polysaccharide thickeners establish them as preferred thickeners. Guar gum, a galacto-mannan, and its derivatives are the most widely used thickeners. Cellulose derivatives including hydroxyethylcellulose and carboxymethylhydroxyethylcellulose are also commonly used.
Molecular weights of thickeners generally range from about 500,000 to 3,000,000. Typically, apparent viscosity of the fracture fluid at operating shear rates (about 170 reciprocal seconds in the wellbore annulus) is raised relative to water by a factor of 500 to 1000. This requires thickener concentrations ranging from 20 to 50 lbs. per 1000 gallons of water.
Wells are currently being drilled deeper than before, and consequently operating temperatures in fractured formations are increasing. Temperatures between 200.degree. F. and 300.degree. F. are commonly encountered in producing oil and gas wells. At higher temperatures, higher thickener loadings are required to achieve required viscosification. However, thickener loading levels have reached their practical limit in cost and pump-ability. This problem is solved by adding crosslinking agents to the fracture fluids. Crosslinking agents form linkages between thickener macromolecules as the fluid is pumped into the well. Crosslinking increases the viscosity of the fracture fluid, thus extending upward the effective working temperature of the thickeners.
Commercial high temperature crosslinking agents include polyvalent metal ions such as Cr(VI), Cr(III), Sb(V), Sb(III) Ti(IV), Al(III), Zr(IV), and also borate. The metal ions are associated with a suitable polydentate anion such as lactate. Zirconium(IV), titanium(IV) and borate ion are currently the preferred crosslinkers for high temperature service.
When fracturing is complete, the fracture fluid must be expelled from the fissures to allow resumption of oil or gas production. The viscosity of the fracture fluid in the formation must be reduced so that it can be expelled. This viscosity reduction is generally called "breaking" the thickener.
The viscosity of aqueous hydratable polymer solutions will break spontaneously over an extended period due to biological or thermal degradation, but lost production time makes it impractical to wait. Therefore, chemical accelerators called "breakers" are added to the fracture fluid to induce and control viscosity breaking. Commonly used breakers for low temperature wells include enzymes, acids, and oxidizing agents. Peroxygen compounds are preferred for high temperature wells. Peroxygens decompose into free radicals EQU ROOR.fwdarw.2 RO.cndot.
that can break intermolecular polymer bonds in thickeners via a chain reaction mechanism; and they leave no objectionable decomposition residue.
Control of time to viscosity break is critical and has been intensively studied. Premature breaking can decrease the number and/or length of fractures, which reduces the effectiveness of the fracture operation. Too long a delay after fracture is undesirable because valuable production time is lost. Fracture operations take from about 30 minutes to eight hours to complete. After the treatment, the fluid may be expected to return to the surface in as early as 24 hours. Accordingly, break times ranging from four hours to 24 hours are required.
Breaktime is controlled primarily by selecting a peroxygen with a requisite rate of decomposition versus temperature profile and secondarily by the amount of peroxygen added to the fracture fluid. A characteristic of peroxygen compounds is that they are stable up to a critical temperature and then, as temperature is raised, they decompose over a temperature range, with the decomposition rate increasing exponentially with absolute temperature. Accordingly, a critical parameter in selecting a peroxygen for a specific well application is its decomposition temperature range; the peroxygen must decompose in the temperature range prevailing in the well. In addition, the concentration of peroxygen can be adjusted to control time to break--adding more breaker to reduce time to break--so that the thickener does not break until after the well fracture is completed, and the time to break is not unreasonably longer than the time to complete well fracture.
Commercial peroxygen breaker compounds include sodium perborate, sodium percarbonate, hydrogen peroxide, potassium diperphosphate, and the salts of monopersulfuric acid and dipersulfuric acid. Other suitable peroxygens include tertiarybutylhydroperoxide, potassium diperphosphate, and the ammonium and alkali metal salts of monopersulfuric acid and ammonium and alkali metal salts of dipersufuric acid.
For low temperature service, 80.degree. F. to 140.degree. F., an activator is commonly added to the fracturing fluid to induce decomposition of the breaker. The activator is usually a coordination compound comprising a ligand and a metal atom capable of existing in solution in two oxidation states. Desirable activators include tertiary amines, 9,10-orthophenanthroline ferrous sulfate complex (ferroin) and iron and copper complexes of catechol.
Currently, the industry is searching for breakers that work at the higher temperatures, 200.degree. F. to 300.degree. F., encountered in deeper wells. Group IA and IIA salts of the perphosphate ion have been proposed as high temperature breaker candidates because the perphosphate ion decomposes in the required temperature range: EQU Mx[O.sub.2 P(O)O].sub.2
where X is 4 for a group 1A metal and 2 for a group IIA metal. Tetrapotassium perphosphate is one perphosphate salt currently proposed as a high temperature breaker. We, however, have discovered that perphosphate salts have deficiencies which preclude their use as high temperature breakers.
As previously discussed, at higher well temperatures exceeding 200.degree. F., a potent crosslinker such as Ti or Zr is required to supplement the thickener. We have observed that when a group 1A or group 2A tetraphosphate salt is added to the fracture fluid, it complexes with metal crosslinkers to such an extent that the crosslinking effectiveness of the metal is significantly impaired. Accordingly, group IA and group 2A perphosphates are not suitable high temperature breakers.
Accordingly, there is need for a breaker for wells operating above 200.degree. F. which timely and effectively breaks the fracture fluid viscosity and which is compatible with the metal crosslinkers added to high temperature fracture fluids.